The present invention relates to the treating of wells and more particularly to the selective treatment of formation strata by temporary closing of perforations in the well casing during the treatment by means of ball sealers.
In the drilling of oil and gas wells numerous formations are penetrated, some containing oil and/or gas, water or being substantially devoid of fluids. In order to isolate the various formations penetrated by the well, the usual practice in completing oil and gas wells is to set a string of pipe, known as casing, in the well and placing cement around the outside of the casing. To establish fluid communication between the hydrocarbon bearing formation and the interior of the casing, the casing and its cement sheath are perforated.
At various times during the life of the well, it may be desirable or necessary to increase or restore the production rate of hydrocarbon by an appropriate stimulation treatment such as acid treatment or hydraulic fracturing. If only a short, single production zone in the well has been perforated, the treating fluid will flow in the zone where it is required. However, as the length of the perforated production zone or the number of perforated production zones increases the direction of the treatment fluid to the production zones where it is required becomes more difficult. The treatment fluid will tend to follow the course of least resistance and will most likely be consumed in those zones of highest permeability where it is least required, while the less permeable zones which require treatment would be left virtually untreated.
To overcome this problem and secure treatment of less permeable zones, the art has developed over the years several means of diverting the treating fluid from the most permeable to the less permeable zones.
The earliest means of diverting acid treating fluids were the use of oil insoluble soaps and gel materials to block the permeable zones. Thereafter downhole mechanical means, known as packers were devised for diversion. Although packers are effective, they are quite expensive due to the involvement of associated work-over equipment required during the tubing-packer manipulations. In addition, there is substantial increase in costs as the depth of the well increases.
As a result, considerable effort has been devoted to the development of alternative diverting methods, such as crushed naphthalenes, crushed oyster shells and limestone as blocking agents, commonly referred to as particulate diverting agents, and ball sealers. One of the most popular and widely used diverting techniques over the past 20 years has been the use of small rubber-coated balls, known as ball sealers to seal off the perforations inside the casing.
These ball sealers are pumped into the wellbore along with the formation treating fluid and are carried down the wellbore and onto the perforations by the flow of fluid through the perforations into the formation. The balls seat onto the perforations and are held there by the pressure differential across the perforation.
The major advantages which contributed to the popularity of the ball sealers are their ease of use, the positive shut off which was obtained independently of the formation and the resultant absence of formation damage.
The ball sealers of the prior art were simply injected into the well at the surface and transported by the treating fluid. Other than a surface ball injector no special or additional treating equipment was required. The ball sealers are designed to have an outer covering sufficiently compliant to seal a jet formed perforation and to have a solid rigid core which resists extrusion into or through the perforation. Therefore, the ball sealers will not penetrate the formation and permanently damage the flow characteristics of the well.
Until recently, ball sealers had four principal characteristics: (1) they are chemically inert in the environment of use, (2) they seal without extruding into the formation, (3) they must release from the perforation when the pressure differential across the perforation is relieved and (4) they are more dense than the treating fluid and sink to the bottom of the well when not seated in a perforation.
Although, the prior art ball sealers were quite successful, the seating efficiency of the high density ball sealers in the perforations was quite low and erratic. To overcome this problem generally an excess of balls beyond the available perforations were pumped into the well.
However, it has recently been discovered that ball sealers having a density less than the treating fluid have 100% seating efficiency. Although, the ball sealers having less density than the treating fluid may be fed from the surface, it is frequently desirable that the placement of these balls occur downhole through tubing located in the well casing.